23. Assignment of Proceeding
Timothy Alan Simon is the assigned Commissioner and Richard Smith is the assigned ALJ in this proceeding.
1. Notice of the Application appeared in the Commission's April 2, 2010 Daily Calendar.
2. Protests to the Application were filed on May 3, 2010 by DRA, TURN, IP, SCE, SCGC, and jointly by Watson and the CCC, and responses to the Application were filed on April 29, 2010, by Long Beach, and on May 3, 2010 by Shell.
3. D.06-12-031 established the FAR system to allocate and prioritize access to the SoCalGas gas transmission system, and requires the Commission to review how the system of FAR has operated, the impact the FAR system has had on end-use customers, market participants, and the gas market in southern California, and whether any changes or modifications to the FAR system are needed.
4. When compared to the period prior to FAR implementation, the FAR system has substantially reduced but not eliminated scheduling uncertainty. Much of the continuing scheduling uncertainty results from receipt point or system-wide capacity constraints caused by scheduled maintenance activities or OFO events.
5. On average, 31 percent more nominated volumes were confirmed into the SDG&E/SoCalGas system after implementation of the FAR system than before implementation. Prior to FAR implementation, 65 percent of nominated volumes were confirmed into the SDG&E/SoCalGas system. After implementation of the FAR system, and including scheduled maintenance periods and OFO events, almost 96 percent of nominated volumes were confirmed during the period between October 2008 and September 2010. Excluding the August 2009 to December 2009 prolonged maintenance period, 99 percent of nominated volumes were confirmed into the SDG&E/SoCalGas system.
6. The percentage of nominated volumes confirmed into the SDG&E/SoCalGas system increased significantly under the FAR system, even during periods when maintenance activities reduced receipt point capacities and OFO events reduced system capacity. During the August 2009 to December 2009 prolonged maintenance period, 88 percent of the nominated volumes were confirmed into the SDG&E/SoCalGas system.
7. The city-gate pool authorized by D.06-12-031 facilitates gas commodity exchanges at the SoCalGas city-gate and benefits buyers and sellers of natural gas by permitting customers to aggregate gas supplies from multiple receipt points on the SDG&E/SoCalGas system.
8. The increased trading volumes through the Intercontinental Exchange have contributed to a competitive market at the SoCalGas city-gate pool for buyers and sellers of natural gas.
9. The FAR system has preserved shippers' flexibility to exchange their receipt point rights with parties holding FAR rights at other receipt points in a manner similar to that existing prior to FAR implementation.
10. The name "Backbone Transportation Service" more accurately describes the service of transporting gas received at receipt points over the SDG&E/SoCalGas backbone transmission lines for delivery to the SDG&E/SoCalGas city-gate.
11. Currently, SDG&E/SoCalGas continue to sell additional FARs during OFOs or maintenance periods when receipt point or system capacity is constrained and cuts to firm nominations are necessary.
12. Continuing to sell FARs when system capacity is reduced leads to system-wide windowing of FARs, resulting in significant cuts to holders of long-term FARs.
13. Limiting the sale and exchange of FARs at receipt points where capacity has been reduced for any reason, including scheduled maintenance, will enable customers holding FARs at a constrained point to know the extent to which their gas will flow at that receipt point.
14. Prohibiting the sale of additional, incremental FARs at any receipt point once an OFO has been announced will preserve the value of FARs because a shipper holding FARs on an OFO day will not see its rights further reduced through proration resulting from additional FAR sales.
15. The availability of reservation charge credits could encourage shippers to purchase excess incremental short-term FARs to increase their share of any windowed FARs, thereby exacerbating capacity constraints and increasing scheduling uncertainty.
16. Requiring the System Operator to continue to pay FAR rates, including the in-kind fuel factor, is consistent with Res. G-3435 that required the System Operator to pay applicable firm or interruptible access charges during the first three-year FAR cycle.
17. Receipt point pools will allow shippers to consolidate their various gas deliveries from upstream pipelines into a pool from which they can then nominate under SoCalGas' scheduling protocols.
18. Allowing pool-to-pool transfers at individual receipt points will facilitate commodity trading and supply administration at individual receipt points into the SDG&E/SoCalGas system.
19. Operational problems could occur if gas delivered to one receipt point was transferred to a second receipt point without gas physically present at the second receipt point.
20. From September 24, 2008 to March 2, 2010, 40 parties participated in the secondary market, completing 264 transactions with contract terms of one day to three years. The volume-weighted average price paid for FARs in the secondary market was $0.048, or 103 percent of the volume-weighted average FAR rate.
21. Only eight secondary market transactions between October 1, 2008 and December 31, 2009 reached the 125-percent cap, and only two set-aside holders sold short-term rights totaling 9,990 Dth/day in the secondary market.
22. Three secondary market transactions that were at the maximum rate of
125 percent occurred on days when OFOs were called and one transaction occurred during a maintenance period when capacity was reduced.
23. Building functionality into the EBB system and associated systems to allow customers the option to aggregate their firm capacity into one contract number for each receipt point will simplify the SoCalGas/SDG&E scheduling process, facilitate exchanges and transfers of firm capacity between receipt points and the secondary market transaction process, and provide customers other administrative benefits.
24. Modifications to the SDG&E/SoCalGas information technology systems will allow customers the option to aggregate their firm capacity into one contract number for each receipt point.
25. When the expansion of the Kern River Pipeline is completed, SDG&E/SoCalGas will be able to offer 50 MMcfd of additional capacity at the Kramer Junction receipt point.
26. Additional adjustments and modifications may be needed as we gain more experience with the FAR system and as the southern California gas market evolves.
27. The recommendations put forth in the JRO are the result of arms-length negotiations between all of the parties and are uncontested.
28. Most of the active parties in this proceeding support or do not oppose the recommendations presented in the JRR.
1. An assessment of the FAR system should compare the performance of the SDG&E/SoCalGas integrated gas transmission system before implementation of the FAR system to its performance after implementation.
2. When compared to the percentage of nominated deliveries confirmed into the SDG&E/SoCalGas system during the period prior to FAR implementation, the system of FAR has been successful in reducing scheduling uncertainty.
3. Changing the FAR service tariff name from "Receipt Point Access" (Schedule G-RPA) to "Backbone Transportation Service" (Schedule G-BTS) is reasonable because this more accurately describes the service of transporting gas received at receipt points over the SDG&E/SoCalGas backbone transmission lines for delivery to the SDG&E/SoCalGas city-gate but does not result in any other changes to the service or the tariff.
4. It is reasonable to add a special condition to newly-named Schedule G-BTS to clarify that G-RPA rates will rely on rates in Schedule G-BTS as a result of the renaming of Schedule G-RPA to Schedule G-BTS.
5. Changing the name of the "FARBA" to the "BTBA" is reasonable because it more clearly describes the service offering, and is consistent with the tariff schedule name change.
6. The BTS revenue requirement of $135.0 million is reasonable and should be adopted for the period from October 1, 2011, until the effective date of rates established in the 2011 SDG&E/SoCalGas TCAP (i.e., January 1, 2013).
7. SDG&E/SoCalGas should be required to prepare a new backbone embedded cost and functionalization study that should be filed with their 2011 TCAP application.
8. It is reasonable to continue providing customers with the firm BTS rate option that is currently offered and billed as a reservation charge.
9. It is reasonable that, during the three-month period from October 1, 2011 to January 1, 2012, the SFV rate amortize the balance in the BTBA as of July 31, 2011.
10. The assumed capacity of 3100 Mdth/day is reasonable and should be used as the billing determinant when calculating the SFV firm reservation rate that will be in effect during the fifteen-month period from October 1, 2011 to
January 1, 2013.
11. A two-part firm service MFV rate option consisting of a fixed reservation charge and a usage charge billed on a volumetric basis is reasonable because an MFV rate option will help lower-load-factor customers manage their capacity costs and aid shippers that are not able to fully use their backbone capacity.
12. It is reasonable for the MFV rate to amortize the balance in the BTBA as of July 31, 2011, during the three-month period from October 1, 2011 to January 1, 2012.
13. The assumed capacity of 2634 Mdth/day is reasonable and should be used as the billing determinant when calculating the usage (volumetric) component of the MFV charge that will be in effect during the 15-month period from October 1, 2011 to January 1, 2013.
14. It is reasonable to expect that the amount of capacity that will be sold during the 15-month period from October 1, 2011 to January 1, 2013 will decrease in response to the higher rates resulting from this decision.
15. It is reasonable to use 3100 Mdth/day as the billing determinant when calculating the reservation (fixed) rate component of the MFV charge that will be in effect during the 15-month period from October 1, 2011 to January 1, 2013.
16. Recovering 80 percent of the backbone revenue requirement through the fixed component of the MFV rate and 20 percent through the volumetric component is reasonable.
17. It is not reasonable to price the lower priority "interruptible" service higher than "firm" service.
18. It is reasonable to use 3100 Mdth/day as the billing determinant when calculating the interruptible rate that will be in effect during the 15-month period from October 1, 2011 to January 1, 2013.
19. Establishing an in-kind fuel charge, assessed only on delivered volumes, to recover the cost of compression fuel used to move gas from receipt points to market centers is reasonable and consistent with the Commission's desire to establish cost-based FAR charges.
20. Except for the in-kind fuel factor that should be adjusted quarterly based on the fuel factor from the prior quarter, it is reasonable to annually adjust BTS rates because this will avoid large over-collection or under-collection of revenues. However, adjustments should not be made to BTS rates on January 1, 2012, because three months is not enough time to reflect seasonal revenue variations.
21. Requiring qualifying interstate contracts to have a minimum term of
12 months and be in effect two months prior to the Open Season beginning date to be eligible for Step 1 set-asides is reasonable because it accommodates Applicants' desire to better match core customers' short-term contracting practices and reliability needs, provides customers adequate time to prepare for Step 2 bidding, and resolves parties' concerns about the potential for the Utility Gas Procurement Department to broker FAR rights to constrained receipt points.
22. Long Beach's core load should be treated the same as the core load of SDG&E/SoCalGas and other wholesale customers.
23. It is reasonable to qualify an upstream pipeline contract associated with a wholesale customer's long-term firm gas supply agreement for a Step 1 set-aside because it ensures that supply agreements such as Long Beach's are treated similarly to other qualifying upstream contracts.
24. Because the amount of time between the deadline for qualifying interstate contracts for Step 1 set-asides and the start of the Step 2 bidding process has been reduced, it is reasonable to require SDG&E/SoCalGas to provide a minimum of two months notice on the available capacity after set-asides are selected and to promptly provide notice of the potential for set-aside quantities so that Open Season participants have sufficient notice and time to prepare for the Step 2 bidding process.
25. It is reasonable to change the Step 1 set-aside from "must-take" to "up-to" as an option for all customers, including the Utility Gas Procurement Department because the Utility Gas Procurement Department should have the same flexibility as other customers to take all, some, or no set-asides at each receipt point.
26. Giving all core customers, including the Utility Gas Procurement Department, a seasonal differentiation of the bidding rights for Step 2, with no preferential treatment for any customer, is reasonable because it provides customers with bidding rights flexibility that will benefit customers and resolves concerns that the Utility Gas Procurement Department could receive preferential treatment.
27. It is reasonable to eliminate Step 3B from the Open Season process and for Step 3A to be renamed "Step 3" because capacity expansion requests can be addressed through the procedures set forth in SDG&E/SoCalGas Gas
Rule No. 39.
28. It is reasonable to shorten the re-contracting period from two weeks to three days because a three-day period will provide customers sufficient time to re-contract receipt point allocations, and because FAR holders may subsequently conduct transactions on a continuous basis through the SoCalGas EBB.
29. It is reasonable to prohibit the sale of FARs at any receipt point once an OFO has been announced and to limit the sale and exchange of FARs at receipt points where capacity has been reduced for any reason because this will provide additional certainty to FAR holders.
30. The scheduling priorities adopted in this decision are reasonable because they increase certainty for shippers, and resolve concerns that scheduled nominations made in earlier cycles will be cut as a result of new nominations made in later cycles.
31. It is reasonable to provide parties an opportunity in the 2012 SDG&E/SoCalGas Customer Forum to revisit the scheduling priorities adopted in this decision, and to consider for approval via advice letter process any proposed changes to the adopted scheduling priorities.
32. The proposal to establish reservation charge credits should be denied because such credits may encourage shippers to purchase excess incremental short-term FARs in order to enlarge their share of windowed FARs.
33. It is reasonable to provide customers who have a G-RPA1 FAR agreement extending beyond October 1, 2011 with the option to turn back the contract to SDG&E/SoCalGas effective September 30, 2011, because constraints caused by scheduled maintenance events and OFOs may have prevented customers from fully using their FARs, and turning back capacity will allow those customers to avoid continuing to pay the higher FAR reservation charges adopted in this proceeding during the remainder of the term of the multi-year contract.
34. It is reasonable to require customers wishing to exercise the option to turn back a contract to SDG&E/SoCalGas to provide SDG&E/SoCalGas notice of intent to turn back capacity not less than two months prior to the start of the 2011 Open Season.
35. Requiring the System Operator to continue to pay the FAR rate when transporting supplies needed to maintain flowing gas requirements on the SoCalGas system is reasonable.
36. Establishing receipt point pools is reasonable because receipt point pools will provide greater flexibility to shippers and promote administrative efficiency.
37. Receipt point pools are reasonable as long as the individual customer pools are limited to receipts and deliveries out of a specific receipt point and transactions between pools are limited to those between pools identified with the same receipt point.
38. Because modifications to the SDG&E/SoCalGas information technology systems that are needed to establish receipt point pools might not be ready by October 1, 2011, it is reasonable for modifications to the SDG&E/SoCalGas information technology systems that are needed to establish receipt point pools to be implemented on a phased-in basis as soon thereafter as they are ready.
39. It is reasonable to recover the cost to implement receipt point pools from the rates charged to BTS customers through the BTBA because receipt point pools will benefit BTS customers.
40. Deferring consideration of the proposal to eliminate the 125-percent cap on secondary market transactions to the SDG&E/SoCalGas 2011 TCAP is reasonable because it will allow parties to gain experience with the new rates and other modifications to the FAR system adopted by this decision.
41. It is reasonable to build functionality into the SDG&E/SoCalGas EBB system and associated systems to allow BTS customers the option to aggregate their firm capacity into one contract number for each receipt point.
42. It is reasonable for the modification to the SDG&E/SoCalGas information technology systems that is needed to allow BTS customers the option to aggregate their firm capacity into one contract number for each receipt point to be implemented by October 1, 2011 or as soon thereafter as it is ready.
43. It is reasonable to recover the cost of building contract aggregation functionality into the SDG&E/SoCalGas information technology systems through the BTBA because this functionality will benefit BTS customers.
44. Because 50 MMcfd of additional capacity will be available at the Kramer Junction receipt point, it is reasonable to offer 550 MMcfd of firm capacity at the Kramer Junction receipt point in the 2011 FAR Open Season.
45. For the upcoming three-year backbone transmission cycle, it is reasonable to record in the BTBA account, instead of the FASRMA, the information technology costs required to enhance BTS.
46. It is reasonable for SDG&E/SoCalGas to record revenues from off-system deliveries in the BTBA instead of the ITBA, so long as the revenues from off-system deliveries from the Southern System first go to pay for the fixed deliveries for the day to offset the System Reliability Memorandum Account (SRMA) costs, and any revenues over and above the day's SRMA costs then be credited to the ITBA for sharing purposes, consistent with the requirements of D.11-03-029.
47. Because this decision authorizes SDG&E/SoCalGas to establish an in-kind fuel factor to recover the cost of fuel used to operate backbone transmission compressors, and because the in-kind fuel factor will be assessed on BTS customers, it is reasonable to discontinue recording transmission fuel costs in the ITBA.
48. The modifications to the FAR system adopted in this decision should not alter the revenue recognition process for existing SoCalGas shareholder-funded incentive programs.
49. It is reasonable to provide parties an opportunity to propose changes to the FAR system in the 2011 TCAP because this will provide a way to consider further modifications to the FAR system that may be necessary.
50. Consistent with the Phase II Settlement adopted in D.09-11-006, the 2011 TCAP should not be limited only to considering proposed changes to the provisions adopted by this decision, but to also provide parties an opportunity to propose other changes to the FAR system that are not appropriate for consideration in the Customer Forum.
51. Except for the scheduling priorities adopted in this decision that should be re-examined in the 2012 SDG&E/SoCalGas Customer Forum, it is reasonable that the modifications adopted by this decision as identified in Exhibit JRO-1 should remain in effect during the three-year backbone transmission cycle beginning on October 1, 2011, and that any operational changes to the FAR system adopted in the 2011 TCAP should not become effective until the three-year backbone transmission cycle beginning October 1, 2014.
52. Although the JRO and JRR were not filed as formal settlements via separate motion, the JRO and JRR recommendations comply with Rule 12.1 in all other respects.
53. The JRO and the JRR satisfy the applicable settlement standards of
Rule 12.1(d) and therefore should be provided the same deference the Commission accords settlements generally.
54. The recommendations presented in the JRO and the JRR do not contravene or compromise any statutory provision or prior Commission decision, are reasonable, consistent with the law, and in the public interest.
55. Because the JRR recommendations are presented as an integrated package of unbundled backbone transmission revenue requirement and rate recommendations, all of the JRR recommendations should be approved.
56. A.10-03-028 should be closed.
IT IS ORDERED that:
1. The "Receipt Point Access" tariff (Schedule G-RPA) is renamed "Backbone Transportation Service" (Schedule G-BTS).
2. The "Firm Access Rights Balancing Account" is renamed the "Backbone Transmission Balancing Account."
3. For the period from October 1, 2011, until the effective date of rates established in the 2011 San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) Triennial Cost Allocation Proceeding (i.e., January 1, 2013), SDG&E and SoCalGas must unbundle
$87.2 million from end-use transportation rates in addition to the $44.8 previously unbundled for a total backbone transmission system revenue requirement of $135.0 million that must be recovered through Backbone Transportation Service rates.
4. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) must prepare a new backbone embedded cost and functionalization study that must be filed with their 2011 Triennial Cost Allocation Proceeding application. Prior to the study, SDG&E/SoCalGas must confer with interested parties to discuss study data, scope, and methodology.
5. The Backbone Transportation Service revenue requirement is included in the scope of the 2011 San Diego Gas and Electric Company/Southern California Gas Company Triennial Cost Allocation Proceeding.
6. San Diego Gas & Electric Company and Southern California Gas Company must offer firm Backbone Transportation Service under a one-part straight fixed-variable (SFV) rate, billed as a reservation charge under Schedule G-BTS, and calculated to recover the unbundled backbone revenue requirement and to amortize balances accumulated in the Backbone Transmission Balancing Account (BTBA). During the three-month period from October 1, 2011 to January 1, 2012, the SFV rate must amortize the balance in the BTBA as of July 31, 2011. During the fifteen-month period from October 1, 2011 until January 1, 2013, the SFV firm reservation rate must use a billing determinant that is based on an assumed capacity of 3100 thousand decatherms/day.
7. San Diego Gas & Electric Company and Southern California Gas Company must offer a two-part firm Backbone Transportation Service modified fixed-variable rate option consisting of a fixed reservation charge and a usage charge billed on a volumetric basis.
8. During the three-month period from October 1, 2011 to January 1, 2012, the Backbone Transportation Service modified fixed-variable rate option must amortize the balance in the Backbone Transmission Balancing Account as of
July 31, 2011.
9. During the period from October 1, 2011 to January 1, 2013 (the effective date of revised rates to be established in the 2011 San Diego Gas & Electric Company and Southern California Gas Company Triennial Cost Allocation Proceeding), the reservation (fixed) rate component of the modified fixed-variable (MFV) rate option must be based on an assumed throughput of 3100 thousand decatherms (Mdth)/day and the usage component of the MFV rate option must be based on an assumed throughput of 2634 Mdth/day.
10. Eighty percent of the Backbone Transportation Service revenue requirement must be recovered through the fixed (i.e., the reservation charge) portion of the modified fixed-variable (MFV) rate option and 20 percent of the revenue requirement must be recovered through the variable (i.e., the volumetric charge) portion of the MFV rate option.
11. San Diego Gas & Electric Company and Southern California Gas Company must offer a one-part volumetric interruptible rate that is equal to the daily straight fixed-variable rate on a 100-percent load factor basis.
12. Effective October 1, 2011, San Diego Gas & Electric Company and Southern California Gas Company must establish an in-kind fuel factor, initially set at 0.22 percent of the total volume of natural gas to be delivered at the receipt point and updated quarterly based on the fuel factor determined from the prior quarter data. Any applicable volumetric charges must be charged only on scheduled volumes net of shrinkage.
13. The following illustrative Backbone Transportation Service rates are approved, effective October 1, 2011. The actual rates charged beginning October 1, 2011 will reflect the balance in the Backbone Transmission Balancing Account as of July 31, 2011, and, as a result, the actual rates will differ from those listed here:
Rate Element |
Adopted Rate |
Straight Fixed-Variable Reservation Charge ($/decatherms (dth)/day) |
$0.11269 |
Modified Fixed-Variable Reservation Charge ($/dth/day) |
$0.09015 |
Modified Fixed-Variable Volumetric Charge ($/dth) |
$0.02653 |
Interruptible Volumetric Charge ($/dth) |
$0.11269 |
14. San Diego Gas & Electric Company (SDG&E)/Southern California Gas Company (SoCalGas) must revise Backbone Transportation Services (BTS) rates on January 1, 2012 through the SDG&E/SoCalGas Annual Regulatory Update to amortize the 2011 year-end balance in the Backbone Transmission Balancing Account (BTBA). Beginning January 1, 2013 and each January 1 thereafter, SDG&E/SoCalGas must revise BTS rates through the SDG&E/SoCalGas Annual Regulatory Update to amortize balances accumulated in the BTBA during the previous year, and 2) to adjust the straight fixed-variable and modified fixed-variable reservation charges using the actual firm contracted capacity and interruptible sales experienced during the preceding October 1 through September 30 period.
15. The Schedule G-BTS Step 1 set-aside eligibility criteria is revised to require qualifying interstate contracts to have a minimum term of 12 months and be in effect two months prior to the Open Season beginning date. The total set-aside provided to the Utility Gas Procurement Department or any other core customer must not exceed the customer's average daily usage during the Base Period, as defined in Special Condition 32 of Schedule G-BTS.
16. Schedule G-BTS is revised to allow a wholesale customer a Step 1 set-aside up to the wholesale customer's average daily core usage during the Base Period, as defined in Special Condition 32 of Schedule G-BTS, based on the wholesale customer's (1) qualifying upstream pipeline contracts and/or (2) a suppliers' upstream pipeline contracts associated with the average daily contract quantity set forth in the wholesale customer's long-term firm gas supply agreement with that supplier to serve its core load. If the set-aside is based on the second option, the wholesale customer must identify the firm upstream capacity rights held by its supplier that are in place at least two months prior to the Step 1 assignment process for a term of 12 months or longer during the applicable three-year backbone transmission cycle.
17. San Diego Gas & Electric Company and Southern California Gas Company must provide notice of the potential for set-aside quantities immediately after the deadline for qualifying contracts to be in place, and provide a minimum of two month notices of the available capacity after set-asides are selected.
18. The Step 1 set-aside is changed from "must-take" to "up-to" as an option for all customers, including the Utility Gas Procurement Department. Schedule G-BTS is modified to allow all Step 1 set-asides, including those for the Utility Gas Procurement Department, to be any quantity of the customer's choosing up to the maximum qualifying amount.
19. Schedule G-BTS is modified to provide the Utility Gas Procurement Department monthly bidding rights in Step 2, in addition to annual average bidding rights, so that quantities bid during the summer months that are less than the annual average will be provided as monthly bidding rights during the winter months such that the total yearly bidding rights do not exceed the average historical usage. The actual bidding capability of the Utility Gas Procurement Department must be no different nor be provided any preference over noncore customers.
20. Schedule G-BTS is modified to 1) eliminate Step 3B from the Open Season process, 2) clarify that all capacity expansion requests must be addressed through the procedures in San Diego Gas & Electric Company Gas Rule No. 39 and Southern California Gas Company Gas Rule No. 39, and 3) change the name "Step 3A" to "Step 3." Except for the name change, Step 3A must remain unchanged.
21. Special Condition No. 62 of Schedule G-BTS is modified to shorten to three days the current two-week re-contracting period following the Open Season process, and to clarify that re-contracting may be conducted on a continuous basis through the Southern California Gas Company electronic bulletin board.
22. Once San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) post any notice that identifies a reduced receipt point or transmission zone capacity, SDG&E and SoCalGas must limit the sale and exchange (re-contracting) of firm receipt point capacity to the reduced capacity quantity for that receipt point and transmission zone for the duration of the posted event. SDG&E and SoCalGas must not sell incremental firm receipt point capacity following the announcement of an operational flow order (OFO) for the flow day on which the OFO is called. Once an OFO has been called, SDG&E and SoCalGas may sell only incremental interruptible access capacity for the flow day on which the OFO is called.
23. San Diego Gas & Electric Company and Southern California Gas Company must apply the following scheduling priorities for gas deliveries:
a. Firm primary scheduled quantities in the Evening Cycle (i.e., Cycle 2) will have priority over a new firm primary nomination made in the Intraday 1 Cycle (i.e., Cycle 3).
b. Firm Alternate Inside-the-Zone scheduled quantities in the Evening Cycle will have priority over new Firm Alternate Inside-the-Zone nominations made in the Intraday 1 Cycle.
c. Firm Alternate Outside-the-Zone scheduled quantities in the Evening Cycle will have priority over new Firm Alternate Outside-the-Zone nominations made in the Intraday 1 Cycle.
d. Interruptible scheduled quantities in the Evening Cycle will have priority over new Interruptible nominations made in the Intraday 1 Cycle.
24. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) must apply the same hierarchy of scheduling priorities in Ordering Paragraph No. 23 in going from Intraday 1 Cycle to Intraday 2 Cycle (i.e., Cycle 4). This hierarchy of priorities does not apply to Intraday 3 (i.e.,
Cycle 5) nominations or the elapsed pro rata rule. SDG&E/SoCalGas must not give priority to nominations scheduled in Cycle 1 over those scheduled in
Cycle 2.
25. The scheduling priorities adopted by this decision may be re-examined in the 2012 San Diego Gas & Electric Company/Southern California Gas Company Customer Forum to be convened in Second Quarter, 2012, in accordance with the Customer Forum process set forth in the Biennial Cost Allocation Proceeding Phase II Settlement adopted in Decision 09-11-006. Any proposed changes to the adopted scheduling priorities must be approved by the Commission via the Tier 2 advice letter process.
26. The San Diego Gas & Electric Company and Southern California Gas Company proposal to establish reservation charge credits is denied.
27. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) must provide customers who have a G-RPA1 firm access rights agreement that extends beyond October 1, 2011, the option to turn back their contract to SDG&E/SoCalGas effective September 30, 2011.
28. Customers who have a G-RPA1 firm access rights agreement that extends beyond October 1, 2011, wishing to exercise the option to turn back their contract to San Diego Gas & Electric Company (SDG&E) or Southern California Gas Company (SoCalGas) must provide SDG&E/SoCalGas notice of intent to turn back capacity not less than two months prior to the start of the 2011 Open Season.
29. During the three-year backbone transmission cycle beginning in 2011, the San Diego Gas & Electric Company/Southern California Gas Company (SoCalGas) System Operator must pay Backbone Transportation Service rates, including the in-kind fuel factor, when transporting supplies needed to maintain flowing gas requirements on the SoCalGas system.
30. Southern California Gas Company must establish receipt point pools for the purpose of aggregating in-coming supplies at a particular receipt point, and allow pool-to-pool transfers at the same receipt point without the payment of Backbone Transportation Service charges. No pool-to-pool transfers between different receipt points are allowed.
31. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) should establish receipt point pools in time for the
October 1, 2011 implementation date for the next three-year backbone transmission cycle, if possible. SDG&E/SoCalGas may implement receipt point pools later than October 1, 2011, on a phased-in basis as soon as they are ready.
32. The cost to implement receipt point pools must be recovered from the rates charged to Backbone Transportation Service customers through the Backbone Transmission Balancing Account.
33. Consideration of San Diego Gas & Electric Company's (SDG&E's) and Southern California Gas Company's (SoCalGas') proposal to eliminate the 125-percent cap on secondary market transactions is deferred to the 2011 SDG&E/SoCalGas Triennial Cost Allocation Proceeding (TCAP). The price cap on secondary market transactions will remain at 125 percent of the reservation charge until it is reexamined in the SDG&E/SoCalGas 2011 TCAP.
34. San Diego Gas & Electric Company and Southern California Gas Company must build functionality into the electronic bulletin board system and associated systems to allow Backbone Transportation Service customers to aggregate their firm capacity into one contract number if they so choose for each receipt point for the purposes of nominations and scheduling.
35. To give effect to existing contracts, San Diego Gas & Electric Company and Southern California Gas Company must add a special condition to Schedule G-BTS to clarify that G-RPA rates will rely on rates in Schedule G-BTS as a result of the renaming of Schedule G-RPA to Schedule G-BTS.
36. San Diego Gas & Electric Company and Southern California Gas Company are authorized to increase available firm capacity to 550 million cubic feet/day at the Kramer Junction receipt point in the 2011 Open Season.
37. For the upcoming three-year backbone transmission cycle, San Diego Gas & Electric Company and Southern California Gas Company must record in the Backbone Transmission Balancing Account, instead of the Firm Access and Storage Rights Memorandum Account, the information technology costs required to enhance Backbone Transmission Service.
38. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) are authorized to record revenues from off-system deliveries in the Backbone Transmission Balancing Account (BTBA) instead of the Integrated Transmission Balancing Account. In keeping with the requirements of Decision 11-03-029, the revenues from off-system deliveries from the Southern System must first go to pay for the fixed deliveries for the day to offset the System Reliability Memorandum Account (SRMA) costs, and any revenues over and above the day's SRMA costs then be credited to the ITBA for sharing purposes..
39. San Diego Gas & Electric Company and Southern California Gas Company are authorized to modify the Integrated Transmission Balancing Account so as not to record transmission fuel costs.
40. San Diego Gas & Electric Company and Southern California Gas Company (SoCalGas) must continue using the existing accounting process for calculating base and incremental revenue for the Core Pricing Flexibility Program (also know as the Optional Pricing Tariffs) and the Noncore Competitive Load Growth Opportunities Program. These SoCalGas shareholder-funded incentive programs must remain unaffected by the implementation of the modifications authorized by this decision.
41. The operational changes adopted in this decision apply to the three-year backbone transmission cycle beginning on October 1, 2011. Parties may propose other changes to the firm access rights system in the 2011 San Diego Gas and Electric Company (SDG&E)/Southern California Gas Company (SoCalGas) Triennial Cost Allocation Proceeding (TCAP). Any operational changes that may be adopted in the 2011 SDG&E/SoCalGas TCAP will not become effective until the three-year backbone transmission cycle beginning October 1, 2014.
42. Within 45 days of the effective date of this decision, San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) must file a Tier 2 advice letter (AL) with the Energy Division containing the tariffs needed to implement this decision. The tariffs must be consistent with and comply with today's decision. The AL is subject to protest, and such protests must be filed not later than 20 days after the AL has been filed. SDG&E/SoCalGas must serve the AL by electronic mail on the service list to this proceeding, and on the interested parties who have requested notification of AL filings for SDG&E and SoCalGas.
43. The modifications to the firm access rights system approved in this decision must be implemented after approval of the implementing tariffs, except that modifications to the San Diego Gas & Electric Company and Southern California Gas Company information technology systems that cannot be completed by October 1, 2011 should be implemented as soon thereafter as they are ready.
44. Application 10-03-028 is closed.
This order is effective today.
Dated April 14, 2011, at San Francisco, California.
MICHAEL R. PEEVEY
President
TIMOTHY ALAN SIMON
CATHERINE J.K. SANDOVAL
MARK FERRON
Commissioners
I abstain.
/s/ MICHEL PETER FLORIO
Commissioner
